The deposits of Canadian heavy oil found in the Lloydminster reservoirs exist in thin zones, often only 5 to 20 meters thick, but of considerable lateral extent and sometimes underlain by bottom water. Unlike the bitumen deposits in the Athabasca and Cold Lake reservoirs which are essentially immobile, oil from these unconsolidated deposits flows under normal solution-gas drive primary recovery mechanisms. With the recent introduction of horizontal well drilling, conventional exploitation of these deposits by vertical wells has now been replaced by horizontal wells, sometimes as much as 1000 meters long. The primary recovery scheme now takes advantage of the large contact area possible between the reservoir and the long horizontal wellbore, in addition to the reduced inflow pressure gradients. Oil production (withdrawal) at rates much higher than with the vertical wells in now easily achievable.
One consequence of the rapid and large withdrawal rates from these reservoirs is the equally rapid reduction of reservoir pressure. Additionally, a significant amount of sand is sometimes produced with the oil due to the unconsolidated nature of the formation, and this results in highly expensive well cleanout procedures. As a result, total recoverable oil from these pools is generally no higher than 15% of the original in-place hydrocarbons. Since this primary production phase leaves the reservoir highly pressure depleted yet saturated with at least 80% of the original oil, some form of supplemental or enhanced recovery process is needed to produce additional oil from the reservoir. Among the various possible processes for recovery of this oil, steam injection is generally regarded as the most economical and efficient. Steam can be used to heat the oil, reducing its viscosity and thereby improving its ability to flow to the production well. In some instances steam is also used to drive the mobilized heated oil towards the production means.
Some of the current practices for transporting the steam heat into the reservoir to heat the oil include the use of:
(a) vertical steam injection wells drilled to the same depth as the horizontal producing well, but located at some lateral distance from the horizontal producing well; PA0 (b) vertical steam injectors drilled into the same formation but located immediately above the horizontal producing well; PA0 (c) horizontal steam injectors drilled parallel to the horizontal producing well but located at the same or slightly higher reservoir depth and at considerable lateral distance from the horizontal producing well; PA0 (d) horizontal steam injectors drilled into the same formation but located vertically above the horizontal producing wells.
All these steam injection schemes and well configurations have unique characteristics that make them inadequate for enhanced recovery from the thin mobile heavy oil reservoirs.
In case (a), injected steam must sweep through the inter-well distance between the vertical injector well and the horizontal producing well and, in the process, transfer heat to mobilize the oil which is then produced through the horizontal well. However, it has been found that the high pressures required to inject and disperse the steam towards the horizontal wells also create stress changes in the reservoir. These stresses cause increased movement of sand which inhibits oil production at the well. Additionally, the development of preferred high flow paths between the vertical injector and the horizontal producing well creates a short circuit for steam flow and causes excessive steam production and severe operational problems. As a result of gravity override, the vertical shape of the preferred path limits the area available for heat transfer from steam and hot condensate to make the recovery process economic.
In case (b), thin heavy oil reservoirs do not provide sufficient vertical space to allow placement of a vertical injector above the horizontal production well, especially if there is a bottom water zone below. Also, with injection directly above the producer, the potential for sand displacement into the producing well is increased. Furthermore, more than one vertical steam injector will generally be required to cover the span of the horizontal well adding to the increased cost for this scheme.
Case (c) is illustrated by Canadian Patent 1,260,826 (also U.S. Pat. No. 4,700,779 issued Oct. 20, 1987) issued on Sep. 26, 1989 to Huang et al which discloses a method of recovering hydrocarbons using parallel horizontal wells as steam injection and production wells. Steam is injected into two parallel horizontal wells to stimulate the formation and then the second horizontal well is converted to a production well. However, such steam injection method may not be advantageous if no control is applied to the manner of steam outflow into the reservoir. Steam injected into a horizontal well may not be distributed uniformly into the reservoir because steam flow in the reservoir is usually controlled by heterogeneity along the well. U.S. Pat. No. 5,141,054 issued Aug. 25, 1992 to Alameddine et al. teaches a method of steam injection down a specially perforated tubing to cause uniform steam injection by choked flow and uniform heating along the wellbore.
Case (d) refers to processes based on U.S. Pat. No. 4,344,485 issued Aug. 17, 1982 to Butler which teaches a Steam Assisted Gravity Drainage technique where pairs of horizontal wells, one vertically above the other, are connected by a vertical fracture. A steam chamber rises above the upper well, and, oil warmed by conduction drains along the outside chamber to the lower production well. However, for the thin heavy viscous oil reservoirs, two problems can be identified: firstly, the additional expense required to drill a second horizontal steam injection well above the horizontal producer makes the process uneconomical; secondly, in thin reservoirs there is insufficient vertical space in which to drill another horizontal well within an acceptable vertical distance from the horizontal producer.
Recently, a number of patents have pursued the concept of single horizontal wellbore oil recovery methods. U.S. Pat. No. 5,167,280 issued Dec. 1, 1992 to Sanchez and Hazlett discloses a solvent stimulation process for tar sands reservoirs whereby a viscosity reducing agent is circulated through an inner tubing string into a perforated horizontal well. The recovery of oil is achieved by diffusion of the solvent/solute mixture into the reservoir, and removal of the oil along the horizontal well as the solvent circulation continues. However, despite the recommended use of horizontal wells, solvent processes are commercially impractical because they require long soak times during which the solvent and oil must remain in contact to have any mixing. Also, the wellbore pressure must be lower than the reservoir pressure in order to promote solvent diffusion. Under these conditions, the proportion of injected solvent which preferentially flows out of the reservoir will be substantially greater than that which rises into the reservoir, thus decreasing the effectiveness of the process.
U.S. Pat. No. 4,116,275 issued Sep. 26, 1978 to Butler et al. discloses a cyclic steam stimulation method of recovering hydrocarbon from tar sands formations via a horizontal wellbore completed with slotted or perforated casing means and with dual concentric tubing strings forming two annular spaces. Steam is injected into the reservoir through the second annular space between the liner or perforated casing and the outer tubing, while gas is introduced as insulating medium in the first annular space. Heated oil and steam condensate are produced to the surface through the inner tubing string.
U.S. Pat. No. 5,148,869 issued Sep. 22, 1992 to Sanchez discloses a single wellbore method and apparatus for in-situ extraction of viscous oil by gravity action using steam plus solvent vapour. One serious limitation of this invention in a practical application is that the method hinges on the use of a specially designed horizontal wellbore containing two compartments. Steam flows into the formation through a condult perforated only along the upper portion of the horizontal wellbore, while oil and condensate flowing downwardly from the reservoir collect in a pool around the wellbore and is pulled into an inner compartment perforated essentially only along the base of the wellbore. Using this apparatus with steam injection into the upper perforated conduit, it would be nearly impossible to transport steam effectively to the toe of the horizontal well or distribute the steam uniformly along the well without a short circuit to the production conduit below.
U.S. Pat. No. 5,215,149 issued Jun. 1, 1993 to Lu discloses a process where heavy oil is recovered from reservoirs with limited native injectivity and a high water-saturated bottom water zone. The horizontal wellbore is perforated only on its top side at selected intervals. It contains an uninsulated tubing string inserted to the farthest end. A thermal packer is placed around the tubing to form two separated, spaced-apart perforated intervals along the horizontal well. Thereafter, steam is injected into the reservoir via the perforated interval near the heel of the horizontal well, while oil and steam condensate are removed via the inner tubing string at the distal and of the horizontal wellbore. Three problems can be identified in the application of this process to an unconsolidated heavy oil reservoir. First, a large amount of sand will be transported into the inner production tubing as the steam sweeps through one set of perforation interval then through the reservoir and is produced through the other set of perforated intervals. Secondly, once a communication path is established between the injection interval and production interval, steam will find an easy way to short circuit the reservoir resulting in poor displacement efficiency. Additionally, the scheme will promote very high heat losses as the produced fluids flowing through the tubing are heated by the steam as it enters the heel of the horizontal well.
As indicated, the referenced patents individually have severe limitations which make the processes described impractical and/or uneconomic for field implementation, particularly in an unconsolidated heavy oil reservoir. What is needed is an economic method to thermally stimulate the viscous oil in these reservoirs using the same horizontal wellbores as have already been used for primary production.